[Federal Register Volume 89, Number 148 (Thursday, August 1, 2024)]
[Proposed Rules]
[Pages 62691-62707]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-16697]
=======================================================================
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R07-OAR-2024-0224; FRL-11566-01-R7]
Disapproval and Promulgation of Air Quality Implementation Plan;
Nebraska; Regional Haze State Implementation Plan; Federal
Implementation Plan for Regional Haze; Completion of Remand
AGENCY: Environmental Protection Agency.
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: Pursuant to the Federal Clean Air Act (CAA or Act), the
Environmental Protection Agency (EPA)
[[Page 62692]]
is proposing this action to address the voluntary remand of a portion
of a final rulemaking published in the Federal Register on July 6,
2012, addressing regional haze obligations for the first planning
period in Nebraska. Specifically, we are revisiting and implementing a
Federal Implementation Plan (FIP) applicable to the Gerald Gentleman
Station, owned and operated by the Nebraska Public Power District
(NPPD). In this action, the EPA is proposing a revised FIP that will
limit sulfur dioxide (SO2) emissions at the Gerald Gentleman
Station. The EPA proposes to determine that SO2 emission
reductions are needed to make reasonable progress toward Congress'
natural-visibility goal at Class I areas affected by visibility-
impairing emissions from Nebraska. This proposal addresses only the
remanded portion of the Nebraska FIP.
DATES: Comments must be received on or before September 30, 2024. The
EPA will hold an in-person public hearing in Nebraska and a separate
virtual public hearing. For more information on the in-person and
virtual public hearings, see SUPPLEMENTARY INFORMATION.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R07-
OAR-2024-0224, to the Federal eRulemaking Portal: https://www.regulations.gov. For additional submission methods, please contact
the person identified in the FOR FURTHER INFORMATION CONTACT section.
Docket: The docket for this action is available electronically at
https://www.regulations.gov. Some information in the docket may not be
publicly available via the online docket due to docket file size
restrictions, or content (e.g., CBI). To request a copy of the files,
please send a request via email to [email protected]. For questions
about a document in the docket please contact individual listed in the
FOR FURTHER INFORMATION CONTACT section.
Confidential Business Information (CBI): Do not submit information
containing CBI to the EPA through https://www.regulations.gov. To
submit information claimed as CBI, please contact the individual listed
in the FOR FURTHER INFORMATION CONTACT section. Clearly mark the part
or all of the information that you claim to be CBI. In addition to one
complete version of the comments that includes information claimed as
CBI, you must submit a copy of the comments that does not contain the
information claimed as CBI directly to the public docket through the
procedures outlined in Instructions earlier. Information not marked as
CBI will be included in the public docket and the EPA's electronic
public docket without prior notice. Information marked as CBI will not
be disclosed except in accordance with procedures set forth in 40 Code
of Federal Regulations (CFR) part 2. For the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
To pre-register to attend or speak at the virtual public hearing,
please use the online registration form available at https://www.epa.gov/ne/state-nebraska or contact us via email at
[email protected]. For more information on the virtual public
hearing, see SUPPLEMENTARY INFORMATION.
FOR FURTHER INFORMATION CONTACT: Jed D. Wolkins, Environmental
Protection Agency, Air Planning and Development Branch, 11201 Renner
Boulevard, Lenexa, Kansas 66219; telephone number: (913) 551-7588;
email address: [email protected].
SUPPLEMENTARY INFORMATION: Throughout this document ``we,'' ``us,'' or
``our'' refer to the EPA.
Virtual public hearing: The EPA is holding a virtual public hearing
to provide interested parties the opportunity to present data, views,
or arguments concerning the proposal. The virtual public hearing will
be on September 3, 2024 at 1:00 p.m. Central Time (CT) and will
conclude at 5:00 p.m. CT or 15 minutes after the last pre-registered
presenter in attendance has presented if there are no additional
presenters.
The EPA will begin pre-registering speakers and attendees for the
hearing upon publication of this document in the Federal Register. To
pre-register to attend or speak at the virtual public hearing, please
use the online registration form available at https://www.epa.gov/ne/state-nebraska or contact us via email at [email protected]. The last
day to preregister to speak at the hearing will be August 26, 2024. The
EPA will post a general agenda for the hearing that will list pre-
registered speakers in approximate order at https://www.epa.gov/ne/state-nebraska. Additionally, requests to speak will be taken on the
day of the hearing as time allows.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearing to run either ahead of schedule or behind schedule. Each
commenter will have approximately 3 to 5 minutes to provide oral
testimony. The EPA encourages commenters to provide the EPA with a
written copy of their oral testimony electronically by emailing it to
[email protected]. The EPA may ask clarifying questions during the
oral presentations but will not respond to the presentations at that
time. Written statements and supporting information submitted during
the comment period will be considered with the same weight as oral
comments and supporting information presented at the virtual public
hearing. A transcript of the virtual public hearing, as well as written
copies of oral presentations submitted to the EPA, will be included in
the docket for this action.
The EPA is asking all hearing attendees to pre-register, even those
who do not intend to speak. The EPA will send information on how to
join the public hearing to pre-registered attendees and speakers.
Please note that any updates made to any aspect of the hearing will be
posted online at https://www.epa.gov/ne/state-nebraska. While the EPA
expects the hearing to go forward as set forth above, please monitor
our website or contact us via email at [email protected] to determine
if there are any updates. The EPA does not intend to publish a document
in the Federal Register announcing updates.
If you require the services of a translator or a special
accommodation such as audio description/closed captioning, please pre-
register for the hearing and describe your needs by August 8, 2024. The
EPA may not be able to arrange accommodations without advance notice.
Table of Contents
I. Executive Summary
II. Background
A. Regional Haze
1. Determination of Baseline, Natural, and Current Visibility
Conditions
2. Reasonable Progress and Long-Term Strategy (LTS)
3. Federal Land Manager (FLM) Consultation
B. Previous Actions Related to Nebraska Regional Haze Long-Term
Strategy Requirements for the First Planning Period
C. Prior Litigation and EPA's Motion for Voluntary Remand
III. Overview of Proposed Action
IV. Legal Authority for This Action
V. EPA's Review of the 2012 Federal Implementation Plan on Remand
A. Factor 1--The Costs of Compliance
1. EPA's Evaluation of Costs for BART in the 2012 Proposed and
Final Rule
2. EPA's Updated Cost Evaluation
B. Factor 2--The Time Necessary for Compliance
C. Factor 3--The Energy and Non-Air Quality Environmental
Impacts of Compliance
[[Page 62693]]
D. Factor 4--The Remaining Useful Life of the Source
E. Evaluation of Potential Visibility Impacts and Improvements
VI. Amending the FIP on Remand--Long-Term Strategy Determination for
Gerald Gentleman Station
VII. The EPA's FLM Consultation
VIII. Proposed Action
IX. Environmental Justice Considerations
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution or Use
I. National Technology Transfer Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations and Executive Order 14096: Revitalizing Our Nation's
Commitment to Environmental Justice for All
I. Executive Summary
The CAA's visibility protection program was created in the 1977 CAA
Amendments. In CAA section 169A, Congress declared a national goal to
remedy any existing and prevent any future visibility impairment in
certain national parks, such as Badlands in South Dakota and Rocky
Mountain in Colorado, and national wilderness areas, such as the
Wichita Mountains Wilderness in Oklahoma. Vistas in these areas
(referred to as Class I areas) are often obscured by visibility
impairment such as regional haze, which is caused by emissions from
numerous sources located over a wide geographic area.
In response to a Congressional directive to provide regulations to
the states, the EPA promulgated regulations to address visibility
impairment in 1999. These regulations, which are commonly referred to
as the Regional Haze Rule, established an iterative process for
achieving Congress's national goal by providing for multiple,
approximately 10-year ``planning periods'' in which state air agencies
must submit to the EPA plans that address sources of visibility-
impairing pollution in their states. The first state plans were due in
2007 for the planning period that ended in 2018. The second state plans
were due in 2021 for the period that ends in 2028. This proposal
focuses on remaining obligations from the first planning period of the
regional haze program.
The CAA and Regional Haze Rule require states to submit a long-term
strategy (LTS) that includes such measures as may be necessary to make
reasonable progress toward the national visibility goal for each Class
I area. A central element of the LTS for the first planning period
state plans was the requirement for certain older stationary sources to
install the Best Available Retrofit Technology (BART) for the purpose
of eliminating or reducing visibility impairment within our nation's
most treasured lands. The other central element of a state's LTS is the
requirement to include any additional control measures that are
necessary to make ``reasonable progress'' towards the national goal. To
determine what control measures are necessary to make reasonable
progress and therefore must be included in the LTS, the four statutory
factors must be considered: (1) the costs of compliance, (2) the time
necessary for compliance, (3) the energy and nonair quality
environmental impacts of compliance, and (4) the remaining useful life
of any existing source subject to such requirements. This statutory
requirement is often referred to as a ``four-factor analysis.''
Additionally, when visibility-impairing emissions from multiple states
impact the same national park or wilderness area, the Regional Haze
Rule requires those states to coordinate and consult with one another
to ensure that each state is making reasonable progress toward the
national goal.
Gerald Gentleman Station, located in western Nebraska, is one of
the highest emitters of visibility-impairing pollutants, specifically
SO2, in the nation. These emissions cause or contribute to
visibility impairment in such iconic places as Wind Cave and Badlands
National Parks in South Dakota and Rocky Mountain National Park in
Colorado. To address this visibility impairment, Nebraska submitted its
first regional haze state implementation plan (SIP) on July 13, 2011.
Nebraska included a BART determination for SO2 emissions
from the Gerald Gentleman Station. In July 2012, the EPA disapproved
portions of the state's SIP, including the BART determination for
Gerald Gentleman Station, finding significant flaws in several aspects
of the state's analysis of potential emission control technologies. The
EPA also disapproved the state's LTS for SO2 at Gerald
Gentleman Station to the extent that it relied on the flawed BART
determination. The EPA promulgated a FIP in place of the elements of
the SIP that it disapproved. The EPA determined that BART for Gerald
Gentleman Station was satisfied by the facility's participation in the
Cross-State Air Pollution Rule (CSAPR) national trading program. The
EPA further found that the gap left in the state's LTS by the EPA's
partial disapproval were also satisfied by the CSAPR.
The NPPD, who owns and operates the Gerald Gentlemen Station, and
several environmental groups filed petitions for review of various
aspects of the EPA's 2012 final action. The EPA sought and received a
voluntary remand without vacatur to reconsider the portion of the final
action relating to the LTS for SO2 at the Gerald Gentleman
Station.\1\ After considering relevant facts, the EPA is proposing to
amend its FIP.
---------------------------------------------------------------------------
\1\ The remainder of the 2012 final rule was upheld by the
Eighth Circuit. Nebraska v. EPA, 812 F.3d 662 (8th Cir. 2016).
---------------------------------------------------------------------------
Nebraska remains one of the few states in the nation that does not
have a complete first planning period regional haze plan in place to
protect the national parks and wilderness areas impacted by its
sources. With this action, the EPA is proposing a new FIP that will
satisfy the regional haze statutory and regulatory requirements for the
first planning period.
II. Background
A. Regional Haze
Regional haze is visibility impairment that is produced by a
multitude of sources and activities which are located across a broad
geographic area. These sources and activities emit fine particulate
matter (PM2.5) (e.g., sulfates, nitrates, organic carbon,
elemental carbon, and soil dust) and its precursors (e.g.,
SO2, nitrogen oxides (NOX), and, in some cases,
ammonia (NH3) and volatile organic compounds (VOCs)). Fine
particle precursors react in the atmosphere to form PM2.5,
which, in addition to direct sources of PM2.5, impairs
visibility by scattering and absorbing light. Visibility impairment
(i.e., light scattering) reduces the clarity, color, and visible
distance that one can see.
In section 169A of the 1977 Amendments to the CAA, Congress created
a program for protecting visibility in the nation's national parks and
wilderness areas. This section of the CAA establishes as a national
goal the prevention of any future, and the remedying of any existing,
anthropogenic (manmade) impairment of visibility in 156 national parks
and wilderness areas designated as
[[Page 62694]]
mandatory Class I areas.\2\ Congress added section 169B to the CAA in
1990 to address regional haze issues, and the EPA promulgated the
Regional Haze Rule, codified at 40 CFR 51.308,\3\ on July 1, 1999.\4\
The Regional Haze Rule established a requirement for all states, the
District of Columbia, and the Virgin Islands to submit a regional haze
SIP.\5\ The primary purpose of the Regional Haze Rule is to outline the
requirements for states to develop programs that assure reasonable
progress toward meeting the national goal of preventing any future, and
remedying any existing, impairment of visibility in mandatory Class I
areas which impairment results from manmade air pollution.\6\
---------------------------------------------------------------------------
\2\ Areas designated as mandatory Class I areas consist of
National Parks exceeding 6,000 acres, wilderness areas and national
memorial parks exceeding 5,000 acres, and all international parks
that were in existence on August 7, 1977. 42 U.S.C. 7472(a). In
accordance with section 169A of the CAA, EPA, in consultation with
the Department of Interior, promulgated a list of 156 areas where
visibility is identified as an important value. 44 FR 69122
(November 30, 1979). The extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park expansions. 42 U.S.C.
7472(a). Although states and tribes may designate as Class I
additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to ``mandatory Class I
Federal areas.'' Each mandatory Class I Federal area is the
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i).
When we use the term ``Class I area'' in this action, we mean a
``mandatory Class I Federal area.''
\3\ In addition to the generally applicable regional haze
provisions at 40 CFR 51.308, the EPA also promulgated regulations
specific to addressing regional haze visibility impairment in Class
I areas on the Colorado Plateau at 40 CFR 51.309. The latter
regulations are not relevant here.
\4\ See 64 FR 35714 (July 1, 1999). On January 10, 2017, the EPA
promulgated revisions to the Regional Haze Rule that apply for the
second and subsequent implementation periods. See 82 FR 3078 (Jan.
10, 2017).
\5\ 40 CFR 51.300(b).
\6\ Id. at 51.300(a).
---------------------------------------------------------------------------
To address regional haze visibility impairment, the Regional Haze
Rule established an iterative planning process that requires states to
periodically submit SIP revisions (each periodic revision referred to
as a ``planning period'') to address regional haze visibility
impairment at Class I areas.\7\ Under the CAA, each SIP submission must
contain ``a long-term (ten to fifteen years) strategy for making
reasonable progress toward meeting the national goal,'' and the initial
round of SIP submissions also had to address the statutory requirement
that certain older, larger sources of visibility-impairing pollutants
install and operate BART.\8\ States' first regional haze SIPs were due
by December 17, 2007, with subsequent SIP submissions containing
revised long-term strategies originally due July 31, 2018, and every
ten years thereafter.\9\
---------------------------------------------------------------------------
\7\ See 42 U.S.C. 7491(b)(2); 40 CFR 51.308 (b) and (f); see
also 64 FR at 35768. The EPA established in the Regional Haze Rule
that all states either have Class I areas within their borders or
``contain sources whose emissions are reasonably anticipated to
contribute to regional haze in a Class I area;'' therefore, all
states must submit regional haze SIPs. See 64 FR at 35721. In
addition to each of the 50 states, the EPA also concluded that the
Virgin Islands and District of Columbia contain a Class I area and/
or contain sources whose emissions are reasonably anticipated to
contribute regional haze in a Class I area. See 40 CFR 51.300(b) and
(d)(3).
\8\ See 42 U.S.C. 7491(b)(2)(A); 40 CFR 51.308 (d) and (e).
\9\ See 40 CFR 51.308(b). The 2017 Regional Haze Rule revisions
changed the second period SIP due date from July 31, 2018, to July
31, 2021, and maintained the existing schedules for the subsequent
implementation periods. See 40 CFR 51.308(f).
---------------------------------------------------------------------------
1. Determination of Baseline, Natural, and Current Visibility
Conditions
The Regional Haze Rule establishes the deciview (dv) as the
principal metric for measuring visibility.\10\ This visibility metric
expresses uniform changes in the degree of haze in terms of common
increments across the entire range of visibility conditions, from
pristine to extremely hazy conditions. Visibility is also sometimes
expressed in terms of the visual range or light extinction. Visual
range is the greatest distance, in kilometers or miles, at which a dark
object can just be distinguished against the sky. Light extinction,
expressed in units of inverse megameters (Mm-1), is the
amount of light lost as it travels over distance. The haze index, in
units of dv, is calculated directly from the total light extinction.
The dv is a useful measure for tracking progress in improving
visibility because each dv change is approximately an equal incremental
change in visibility perceived by the human eye. Most people can detect
a change in visibility of one dv.\11\
---------------------------------------------------------------------------
\10\ See 64 FR 35714, 35725-27 (July 1, 1999).
\11\ The preamble to the Regional Haze Rule provides additional
details about the deciview. 64 FR at 35725.
---------------------------------------------------------------------------
The dv is used in expressing Reasonable Progress Goals (RPGs)
(which are interim visibility goals towards meeting the national
visibility goal), defining baseline, current, and natural conditions
and tracking changes in visibility. The regional haze SIPs must contain
measures that ensure ``reasonable progress'' toward the national goal
of preventing and remedying visibility impairment in Class I areas
caused by manmade air pollution by reducing anthropogenic emissions
that cause regional haze.
To track changes in visibility over time at each of the 156 Class I
areas covered by the visibility program (40 CFR 81.401-437), and as
part of the process for determining reasonable progress, states with
Class I areas, must calculate the degree of existing visibility
impairment at each Class I area at the time of each regional haze SIP
submittal and periodically review progress every five years midway
through each 10-year implementation period. To do this, the Regional
Haze Rule requirements for the first planning period \12\ provide that
states must determine the degree of impairment (in dv) for the average
of the 20 percent least impaired (``best'') and 20 percent most
impaired (``worst'') visibility days over a specified time period at
each of their Class I areas. In addition, states must also develop an
estimate of natural visibility conditions for the purpose of comparing
progress toward the national goal. Natural visibility is determined by
estimating the natural concentrations of pollutants that cause
visibility impairment and then calculating total light extinction based
on those estimates. The EPA provided guidance to states regarding how
to calculate baseline, natural, and current visibility conditions in
the first planning period.\13\
---------------------------------------------------------------------------
\12\ The applicable requirements of the Regional Haze Rule for
the first planning period are found in 40 CFR 51.308(d).
\13\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available
at https://www3.epa.gov/ttn/naaqs/aqmguide/collection/cp2/20030901_oaqps_epa-454_b-03-005_estimating_natural%20_visibility_regional_haze.pdf (hereinafter
referred to as ``our 2003 Natural Visibility Guidance''); and
Guidance for Tracking Progress Under the Regional Haze Rule, EPA-
454/B-03-004, September 2003, available at https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf (hereinafter
referred to as our ``2003 Tracking Progress Guidance'').
---------------------------------------------------------------------------
For the regional haze SIPs for the first planning period,
``baseline visibility conditions'' were the starting points for
assessing ``current'' visibility impairment. Baseline visibility
conditions represent the degree of visibility impairment for the 20
percent least impaired days and 20 percent most impaired days for each
calendar year from 2000 to 2004. Using monitoring data for 2000 through
2004, states are required to calculate the average degree of visibility
impairment for each Class I area on the 20 percent least and most
impaired days, based on the average of annual values over the five-year
period. The comparison of initial baseline visibility conditions to
natural visibility conditions indicates the amount of improvement
necessary to attain natural visibility, while the future comparison of
baseline conditions to the then current conditions will indicate the
amount of progress made. In general, the 2000-2004 baseline period is
considered the starting point from
[[Page 62695]]
which improvement in visibility is measured in the first planning
period.
2. Reasonable Progress and Long-Term Strategy (LTS)
The vehicle for ensuring continuing progress towards achieving the
natural visibility goal is the submission of a series of regional haze
SIPs, including a LTS, from the states that have emissions expected to
impact visibility in any Class I area. Additionally, states with Class
I areas must establish two reasonable progress goals (RPGs) (i.e., one
for the ``best'' and one for the ``worst'' days) for each Class I area
within the state for each (approximately) 10-year planning period.\14\
The Regional Haze Rule does not mandate specific milestones or rates of
progress, but instead calls for states to establish goals that provide
for ``reasonable progress'' toward achieving natural visibility
conditions. In establishing RPGs, states must provide for an
improvement in visibility for the most impaired days over the
(approximately) 10-year period of the SIP and ensure no degradation in
visibility for the least impaired days over the same period.\15\
---------------------------------------------------------------------------
\14\ See 64 FR at 35730-37.
\15\ Id.
---------------------------------------------------------------------------
Further, CAA section 169A(b)(2)(B) requires all states to include
in their regional haze SIP a long-term (10-to-15-year) strategy for
making reasonable progress towards the national goal. Consistent with
this statutory obligation, 40 CFR 51.308(d)(3) requires all states
(both downwind and upwind) to ``submit a long-term strategy that
addresses regional haze visibility impairment for each mandatory Class
I Federal area within the state and each mandatory Class I Federal area
located outside the state which may be affected by emissions from the
state.'' \16\ A state's LTS is therefore inextricably linked to the
RPGs \17\ because it ``must include enforceable emission limitations,
compliance schedules, and other measures as necessary to achieve the
RPGs established by states having mandatory Class I Federal areas.\18\
---------------------------------------------------------------------------
\16\ 40 CFR 51.308(d)(3).
\17\ 40 CFR 51.308(d)(1)
\18\ 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------
In establishing its LTS, a state must meet a number of
requirements. First, as a corollary to Sec. 51.308(d)(1)(iv), when a
state's emissions are reasonably anticipated to cause or contribute to
visibility impairment in a Class I area located in another state, the
Regional Haze Rule requires the downwind state to coordinate with the
upwind states in order to develop coordinated emissions management
strategies.\19\ The purpose of the consultation requirement is to
ensure that the upwind states adopt control measures sufficient to
address their apportionment of emission reductions necessary to achieve
reasonable progress and that the downwind state's RPGs properly account
for the visibility improvement that will result from the reasonable
control measures identified and included in the upwind state's LTS.
---------------------------------------------------------------------------
\19\ 40 CFR 51.308(d)(3)(i).
---------------------------------------------------------------------------
Second, where multiple states contribute to visibility impairment
in a Class I area, each state ``must demonstrate that it has included
in its implementation plan all measures necessary to obtain its share
of the emission reductions needed to meet the progress goal for the
area.'' \20\ This requirement addresses situations where an upwind
state agrees to achieve certain emission reductions during the
consultation process, and downwind states rely upon those reductions
when setting their RPGs, but the upwind state ultimately fails to
include sufficient control measures in its LTS to ensure that the
emission reductions will be achieved. In such a situation, the upwind
state's LTS would not meet the statutory or regulatory requirements.
---------------------------------------------------------------------------
\20\ 40 CFR 51.308(d)(3)(ii).
---------------------------------------------------------------------------
Finally, each state ``must document the technical basis, including
modeling, monitoring and emissions information on which the state is
relying to determine its apportionment of emission reduction
obligations necessary for achieving reasonable progress in each
mandatory Class I area it affects.'' \21\ Section 169(A)(g)(1) of the
CAA requires states to determine ``reasonable progress'' by considering
the four statutory factors: (1) The costs of compliance; (2) the time
necessary for compliance; (3) the energy and non-air quality
environmental impacts of compliance; and (4) the remaining useful life
of any potentially affected sources.\22\ Therefore, this provision
requires states to consider downwind Class I areas when they develop
the technical basis underlying their four-factor analysis to determine
which control measures are necessary to make reasonable progress, and
thus need to be a part of their LTS. The regulations further provide
that, ``States may meet this requirement by relying on technical
analyses developed by the regional planning organization and approved
by all State participants.'' \23\ Thus, states have the option of
meeting this requirement by relying on four-factor analyses and
associated technical documentation prepared by a regional planning
organization on behalf of its member states,\24\ to the extent that
such analyses and documentation were conducted. In situations where a
regional planning organization's analyses are limited, incomplete or do
not adequately assess the four factors, however, then states must fill
in any remaining gaps to meet this requirement. States should consider
all types of anthropogenic sources of visibility impairment in
developing their LTS, including stationary, minor, mobile, and area
sources.\25\ At a minimum, states must describe how each of the
following seven factors listed below are taken into account in
developing their LTS: (1) Emission reductions due to ongoing air
pollution control programs, including measures to address ``reasonably
attributable visibility impairment'' (RAVI); (2) measures to mitigate
the impacts of construction activities; (3) emissions limitations and
schedules for compliance to achieve the RPG; (4) source retirement and
replacement schedules; (5) smoke management techniques for agricultural
and forestry management purposes including plans as currently exist
within the state for these purposes; (6) enforceability of emissions
limitations and control measures; (7) the anticipated net effect on
visibility due to projected changes in point, area, and mobile source
emissions over the period addressed by the LTS.\26\
---------------------------------------------------------------------------
\21\ 40 CFR 51.038(d)(3)(iii).
\22\ 42. U.S.C. 7491(g)(1).
\23\ 40 CFR 51.308(d)(3)(iii).
\24\ See WildEarth Guardians v. EPA, 77 F.3d 919 at 944 (10th
Cir. Oct. 21, 2014) (explaining that 40 CFR 51.308(d)(3)(iii)
``permits a State conducting a reasonable-progress determination''
``to rely on [a regional planning organization's] four-factor
analysis.'').
\25\ 40 CFR 51.308(d)(3)(iv); See also 40 CFR 51.301.
\26\ 40 CFR 51.308(d)(3)(v).
---------------------------------------------------------------------------
3. Federal Land Manager (FLM) Consultation
The Regional Haze Rule requires that a state, or the EPA if
promulgating a FIP, consult with FLMs before adopting and submitting a
required SIP or SIP revision or a required FIP or FIP revision. Under
40 CFR 51.308(i)(2), a state, or the EPA if promulgating a FIP, must
provide an opportunity for consultation no less than 60 days prior to
holding any public hearing or other public comment opportunity on a SIP
or SIP revision, or FIP or FIP revision, for regional haze. The EPA
must include a description of how it addressed comments provided by the
FLMs when considering a FIP or FIP revision.
[[Page 62696]]
B. Previous Actions Related to Nebraska's Regional Haze Long-Term
Strategy for the First Planning Period
On July 6, 2012, the EPA took final action on Nebraska's Regional
Haze SIP for the first planning period.\27\ In that final action, the
EPA partially approved and partially disapproved the state's SIP. The
EPA disapproved the state's SO2 BART determinations for
Gerald Gentleman Station Units 1 and 2 and the state's LTS, which had
relied on the state's flawed BART determinations.\28\ The reasons for
the EPA's disapproval are outlined in both the proposed rule and the
final rule.\29\ In the same action, the EPA also promulgated a FIP to
address the deficiencies in Nebraska's Regional Haze Plan. For those
deficiencies associated with the state's SO2 control
decisions for Gerald Gentleman Station Units 1 and 2, the EPA relied on
the CSAPR to meet both the BART requirement and the LTS requirement to
make reasonable progress.\30\ Specifically, the EPA relied on its
finding in a separate national rulemaking that CSAPR provides for
greater reasonable progress on average across all affected Class I
areas than source-specific BART in those states covered by the CSAPR
(the ``Better than BART Rule'').\31\ In that separate national
rulemaking, the EPA revised the Regional Haze Rule to provide that
states could choose to rely on the CSAPR as an alternative to BART.
Consistent with this regulatory provision, the EPA relied on the CSAPR
as an alternative to BART for SO2 emissions from the Gerald
Gentleman Station. In addition, the EPA concluded in the FIP that
reliance on the CSAPR would remedy the deficiency in Nebraska's LTS for
SO2 at the Gerald Gentlemen Station.
---------------------------------------------------------------------------
\27\ 77 FR 40149.
\28\ The EPA approved rest of the Nebraska SIP including these
elements of the LTS. See 77 FR 12770 (March 2, 2012) (proposed
rule); 77 FR 40149 (July 6, 2012) (final rule).
\29\ Id.
\30\ Id.
\31\ 77 FR 33642.
---------------------------------------------------------------------------
C. Prior Litigation and EPA's Motion for Voluntary Remand
Sierra Club, the NPCA, the State of Nebraska, and NPPD filed
petitions for review challenging EPA's final action in the Eighth
Circuit Court of Appeals.\32\ In response to arguments raised by the
Sierra Club and NPCA during briefing on the petitions, the EPA moved
for a voluntary remand without vacatur of the LTS portion of the FIP
for Nebraska as it related to SO2 emissions from the Gerald
Gentleman Station.\33\ The EPA explained in its motion that the
Agency's rationale for declining to require additional SO2
controls at the Gerald Gentleman Station as part of the LTS in its FIP
was not fully or clearly explained. The EPA also stated that the
explanation in the record could potentially be construed in a manner
that was inconsistent with the EPA's interpretation of the relevant
statutory requirements. As a result, the EPA determined that a remand
was appropriate to afford the Agency an opportunity to amend or further
explain its rationale for declining to require additional
SO2 controls beyond the CSAPR in the LTS, more fully respond
to comments submitted by the public, or to take further action if
necessary. The Court granted the remand on March 19, 2015. On January
19, 2017, the EPA Region 7 Administrator signed a proposed FIP that
would have addressed the remanded portion of the Nebraska FIP for the
first planning period. However, subsequent to the Administration
change, the Office of Management and Budget published a memorandum
requesting that any action that had been sent to the Federal Register,
but had not yet published, be immediately withdrawn for review and
approval by the new administration.\34\ After being withdrawn, no
action was taken on the FIP. Therefore, the EPA now is proposing a
similar, updated action to address the remanded portion of the Nebraska
FIP for the first planning period.
---------------------------------------------------------------------------
\32\ NPPD dismissed its petition voluntarily but remained as an
intervenor in the other petitions. See Order, Neb. Pub. Power Dist.
v. EPA, No. 12-3061 (8th Cir. November 4, 2014).
\33\ EPA's Motion for Partial Voluntary Remand, Nebraska. v.
EPA, 812 F.3d 662 (8th Cir. 2015) (No.12-3084).
\34\ 82 FR 8346.
---------------------------------------------------------------------------
III. Overview of Proposed Action
To address the voluntary remand, we are proposing to revise our FIP
so that the LTS adequately addresses SO2 emissions from
Gerald Gentlemen Station. Specifically, the EPA is proposing an
SO2 emission limit of 0.06 lb/MMBtu on a 30-day rolling
average basis for the Gerald Gentleman Station Unit 1 and Unit 2 to
ensure that multiple Class I areas impacted by the Station's emissions
can make reasonable progress toward Congress's natural-visibility goal.
The EPA is also taking comment on the control options and limits
analyzed in this action.
IV. Legal Authority for This Action
The EPA has the authority to revisit its prior FIP actions on
remand. As previously stated, the EPA moved for a partial voluntary
remand of the FIP without admitting error. The Eighth Circuit granted
the motion and remanded the action to the EPA on Marth 19, 2015. Thus,
the EPA has an obligation to complete its action on remand.
On remand, the EPA is taking this action pursuant to CAA sections
110(c)(1), 110(k)(3), and 169A(b)(2). CAA section 169A(b)(2) requires
states to revise their SIPs to contain such measures as may be
necessary to make reasonable progress towards the national visibility
goal. Additionally, CAA section 110(k)(3) authorizes the EPA to
approve, disapprove, or partially approve and partially disapprove a
SIP or SIP revision, and CAA section 110(c)(1) authorizes the EPA to
promulgate a FIP where ``the Administrator . . . disapproves a state
implementation plan submission in whole or in part.'' The EPA's
authority to take such actions under the CAA necessarily provides it
the inherent authority to revisit and amend such actions as necessary.
See Trujillo v. Gen Elec. Co., 621 F.2d 1084, 1086 (10th Cir. 1980). It
is well established that agencies have inherent authority to revisit
past decisions and to revise, replace, or repeal a decision to the
extent permitted by law and supported by a reasoned explanation. FCC v.
Fox Television Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle
Manufacturers Ass'n of the United States, Inc. v. State Farm Mutual
Automobile Insurance Co., 463 U.S. 29, 42 (1983); see also Encino
Motorcars, LLC v. Navarro, 579 U.S. 211, 221-22 (2016). Further, the
Eighth Circuit granted the EPA's request for a voluntary remand, and
this action responds to that remand.
V. EPA's Review of the 2012 Federal Implementation Plan on Remand
In this action, the EPA is proposing to act on the remanded portion
of our FIP as it relates to LTS requirements for SO2 for the
Gerald Gentleman Station. Specifically, the EPA is supplementing the
record with a four-factor analysis for SO2 at Gerald
Gentleman Station. As a result of this analysis, the EPA is proposing a
new FIP with a 0.06 lb/MMBtu emissions limit for SO2 as a
part of Nebraska's LTS. In EPA's final 2012 action, the EPA relied on
the implementation of the previously adopted CSAPR FIP for all Nebraska
Electric Generating Units (EGUs) to satisfy the LTS requirements of the
Regional Haze Rule for SO2, including for the Gerald
Gentleman Station. At the time of the final action, the EPA did not
further evaluate whether, with respect
[[Page 62697]]
to the Gerald Gentleman Station, the CSAPR was an appropriate and
sufficient measure needed in its LTS for making reasonable progress
towards natural visibility conditions at the Class I areas it impacts;
that is, the Badlands, Wind Cave, and Rocky Mountain National Parks.
The environmental petitioners pointed out this deficiency in their
challenge of EPA's final action. The EPA agreed, and thus requested and
was granted a remand.
For the first planning period, Nebraska participated in the Central
Regional Air Planning Association (CENRAP) and incorporated the CENRAP-
developed visibility modeling into their regional haze SIP. The SIP
relied on the CENRAP modeling, which assumed SO2 controls at
a rate of 0.15 lb/MMBtu at Gerald Gentleman Station.\35\ As explained
in our 2012 final action on the Nebraska regional haze SIP, source-
specific CALPUFF modeling shows a significant visibility impact from
Gerald Gentleman Station on South Dakota's Class I areas, Wind Cave and
Badlands National Parks.\36\ The Colorado Department of Public Health
and the Environment also commented on Nebraska's regional haze SIP,
requesting that the state reconsider the question of whether the Gerald
Gentleman Station should install SO2 controls, given Gerald
Gentleman Station's CALPUFF modeled impacts on Rocky Mountain National
Park.37 38 Nebraska consulted with both South Dakota and
Colorado during the first planning period. Based on their BART
determination, Nebraska did not require source-specific BART controls
at Gerald Gentleman Station as part of their LTS in their regional haze
SIP. As explained in our partial disapproval of the state's regional
haze SIP, Nebraska did not include an adequate justification explaining
why controls at the Gerald Gentleman Station were not included as part
of the LTS, nor did Nebraska provide an adequate explanation or
documentation of why their conclusions otherwise satisfied the
requirements of 40 CFR 51.308(d)(3)(iii) to ``determine its
apportionment of emission reduction obligations necessary for achieving
reasonable progress.''
---------------------------------------------------------------------------
\35\ For comparison, the SO2 emission rate at Gerald
Gentleman Station was about 0.58 lb/MMBtu during 2002, which was the
period used as the baseline by Nebraska when it developed its SIP.
In 2015 the emission rate was 0.57 lb/MMBtu. In 2022, the emission
rate was 0.57 lb/MMBtu.
\36\ 77 FR at 12776.
\37\ 77 FR 12776-12777.
\38\ Gerald Gentleman Station CALPUFF modeling visibility
impacts were 1.15 deciview at Rocky Mountain. The source-specific
CALPUFF modeling approach and results are provided in EPA's Analysis
and Modeling TSD.
---------------------------------------------------------------------------
In addition to the CALPUFF modeling used in its BART determination,
Nebraska also used CENRAP CAMx photochemical source apportionment
modeling to identify the pollutants (e.g., sulfates, nitrates) and
source categories (e.g., elevated point EGUs) that most impact
visibility at Class I areas located in surrounding states. A summary of
the annual emissions used for Nebraska elevated point sources and
Gerald Gentleman Station in the 2002 base year and 2018 future year
CENRAP modeling is shown in table 1 of the Analysis and Modeling
Technical Support Document (Analysis and Modeling TSD) for this action.
The EPA reviewed both the 2018 CENRAP CAMx source
apportionment modeling used by Nebraska and the Western Resources Air
Partnership (WRAP) 2018 CAMx source apportionment used by
South Dakota and Colorado to establish RPGs at their respective Class I
areas. In setting their RPGs, both South Dakota and Colorado used the
WRAP 2018 PRP18b modeling platform, which assumed an SO2
control rate of 0.15 lb/MMBtu at Gerald Gentleman, which is similar to
the 2018 CENRAP modeling. The modeled combined emissions at Gerald
Gentleman Station Units 1 and 2 showed SO2 emissions
decreasing from 32,152 ton per year (tpy) in 2002 to 8,732 tpy in 2018
(with controls to achieve the 0.15 lb/MMBtu SO2 emission
limit assumed to be in operation in 2018).\39\ This reduction of the
CAMx modeled SO2 emissions at Gerald Gentleman
Station helps lower the projected SO2-caused light
extinction at Badlands National Park contributed by Nebraska elevated
point sources from 0.98 Mm-1 in 2002 to 0.47 Mm-1
in 2018. The decrease in the SO2 extinction at Badlands
National Park from Nebraska elevated point sources is due to the
decrease in modeled emissions from 2002 to 2018, and in particular the
decrease in modeled SO2 emissions at Gerald Gentleman
Station due to the assumption of the achievement of a 0.15 lb/MMBtu
emission rate in 2018. The EPA therefore finds that the CAMx modeling
performed by both CENRAP and WRAP shows that emissions from Gerald
Gentleman Station contribute to visibility impairment at the Badlands
Class I area in South Dakota.
---------------------------------------------------------------------------
\39\ WRAP-RMC_2002-18_Modeling_Gerald_Gentleman.xlsx in the
docket.
---------------------------------------------------------------------------
In 2012, the EPA evaluated Nebraska's SIP and determined it did not
appropriately address the LTS requirements of the Regional Haze Rule
related to Gerald Gentleman Station. Although there were modeled
visibility impacts and improvements from the installation of cost-
effective controls at Gerald Gentleman Station at Class I areas,
Nebraska did not require any reduction in SO2 emissions from
Gerald Gentleman Station. The EPA partially disapproved Nebraska's LTS
based on the state's reliance on the deficient SO2 control
determination for Gerald Gentleman Station. The EPA also promulgated a
FIP in which we relied on the CSAPR to address this deficiency in
Nebraska's SIP, but the EPA did not conduct a four factor analysis to
evaluate whether additional controls beyond the CSAPR at Gerald
Gentleman Station were required to ensure the SIP included all measures
necessary to obtain Nebraska's share of the emission reductions needed
to make reasonable progress towards the national goal at the Class I
areas its emissions impact. Therefore, in order to provide a more
thorough rationale on its LTS determination, the EPA requested and was
granted a remand in order to provide a more robust explanation.
To properly evaluate whether the CSAPR was sufficient to satisfy
Nebraska's obligation to address the visibility impacts of their
emissions at the Class I areas it affects, the EPA has reviewed the
record from the proposed and final actions. The EPA has found that the
reductions expected (and now observed) from the implementation of the
CSAPR do not equate to the reductions presumed by the CENRAP and WRAP
modeling that were found to be achievable at a reasonable cost by both
Nebraska and the EPA. We are therefore proposing to conclude that the
CSAPR budgets for Nebraska are inadequate to ensure reasonable progress
at neighboring Class I areas.
[[Page 62698]]
The EPA's determination in 2012 that the CSAPR provides for greater
reasonable progress than BART was based on an assessment that the CSAPR
would provide for greater visibility improvement, on average, across
all affected Class I areas.\40\ In our assessment of the relative
impacts of the CSAPR and BART on visibility, the EPA considered
separately the average visibility improvement across the 60 Class I
areas in the eastern portion of the CSAPR modeling domain and the
average impact across all 140 Class I areas in the 48 contiguous states
with sufficiently complete monitoring data to support our analysis.\41\
In both cases, the Agency concluded that the CSAPR would provide for
greater reasonable progress than BART on a regional basis. Both
assessments showed, however, that source-specific BART would provide
for greater visibility improvement than participation in the CSAPR in a
number of Class I areas west of the Mississippi River and east of the
Rocky Mountains, including at the Wind Cave and Badlands National Parks
in South Dakota.\42\
---------------------------------------------------------------------------
\40\ 77 FR 33642 (June 7, 2012).
\41\ 76 FR 82219, 82225-82227 (December 30, 2011).
\42\ 77 FR at 33650; TSD for CSAPR Better-than-BART found at
https://www.regulations.gov/document?D=EPA-HQ-OAR-2011-0729-0014.
---------------------------------------------------------------------------
That being said, as mentioned previously, in addition to the BART
requirements, first planning period regional haze SIPs also have LTS
requirements that are separate and apart from BART. The fact that a
BART alternative provides for greater reasonable progress on average
across a number of Class I areas in order to be considered a valid BART
alternative, does not inherently mean that the same BART alternative
can also be used, without additional explanation or analysis, to
automatically satisfy the LTS requirements to ensure reasonable
progress.\43\ As stated above, like the BART requirements laid out in
CAA 169A(b)(2)(A) and 40 CFR 51.308(e), in order to show that a state's
SIP is also making reasonable progress toward the national goal
pursuant to CAA 169A(a)(1) & (b)(2)(B), it must also meet separate
requirements outlined in 40 CFR 51.308(d). For example, each state must
document the information upon which it is relying to determine its
apportionment of emission reduction obligations necessary for achieving
reasonable progress in each Class I area it affects, which includes
considering the four statutory factors set forth in section
169(A)(g)(1).\44\
---------------------------------------------------------------------------
\43\ 70 FR 39104, 39143-144 (July 6, 2005).
\44\ 40 CFR 51.308(d)(3)(iii); 42 U.S.C. 7491(g)(1).
---------------------------------------------------------------------------
In assessing the impacts of the CSAPR on SO2 emissions
from Nebraska, the CSAPR did not drive comparable SO2
reductions at the Gerald Gentleman Station to those achievable from
SO2 controls. Prior to the CSAPR, Gerald Gentleman Station
had a five-year annual average SO2 emissions of 27,600 tons.
After the CSAPR implementation on January 1, 2015, Gerald Gentleman
Station has had annual SO2 emission ranging from 18,200 to
27,700 tons with an annual average of 22,400 tons from 2015 to
2022.\45\ In the most recent year (2022) of available data, Gerald
Gentleman Station's facility-wide annual SO2 emissions were
21,228 tons, which ranks 3rd nationally across electrical generating
units. Currently, Nebraska receives 68,162 tons of SO2
allowances under the CSAPR and 28,896 tons of SO2 allowances
are given annually to Gerald Gentleman Station. Despite the CSAPR being
a valid BART alternative to fulfill Nebraska's first planning period
BART requirements, because of the amount of the CSAPR allowances
provided to Nebraska, as it relates to its LTS requirements, the CSAPR
has not resulted in any additional SO2 emissions reductions
from Gerald Gentleman Station. Instead, the year-to-year variability
seen in annual emissions is primarily driven by fluctuations in coal
sulfur content and utilization. As an example, if Nebraska had
implemented the 0.15 lb/MMBtu presumptive SO2 limit used in
the CENRAP and WRAP modeling, as relied upon by other CENRAP and WRAP
states, Gerald Gentleman Station would have had annual SO2
emissions ranging from 5,500 to 8,300 tons.\46\ Given the lack of
reductions required by the CSAPR in Nebraska coupled with the history
outlined above regarding Nebraska's consultation with neighboring
states, the EPA is proposing that it is inappropriate to rely on the
CSAPR to ensure reasonable progress toward natural visibility without
further consideration of appropriate SO2 control measures
for Gerald Gentleman Station.
---------------------------------------------------------------------------
\45\ Based on CAMD information. See the file ``CAMD
SO2 annual emissions from GGS20152022.cvs'' in the docket
for this action.
\46\ Based on a conservative 70% reduction in emissions.
---------------------------------------------------------------------------
Therefore, in this action, the EPA has provided an analysis of the
LTS in accordance with 40 CFR 51.308(d) and the CAA 169A(b)(2)(B). This
analysis includes a discussion of the four statutory factors outlined
in CAA 169A(g)(1) to determine whether additional emission reduction
measures are necessary at the Gerald Gentleman Station to fulfill the
LTS requirements of the Regional Haze Rule to ensure reasonable
progress towards the national goal.
To complete the reasonable progress four-factor analysis the EPA
must look at the following: the costs of compliance; the time necessary
for compliance; the energy and non-air environmental impacts of
compliance; and the remaining useful life of any potentially affected
sources.\47\ The Guidance for Setting Reasonable Progress Goals under
the Regional Haze Program \48\ notes the similarity between some of the
reasonable progress factors and the BART factors contained in 40 CFR
51.308(e)(1)(ii)(A),and suggests that the BART Guidelines be consulted
regarding cost, energy and non-air quality environmental impacts, and
remaining useful life. We are therefore relying on our BART Guidelines
for assistance in quantifying and considering those reasonable progress
factors, as applicable.
---------------------------------------------------------------------------
\47\ 40 CFR 51.308(d)(1)(i); 42 U.S.C. 7491(g)(1).
\48\ Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program, June 1, 2007. The 2019 Guidance includes the
June 1, 2007 in its list of other guidance and does not contradict
it. While the 2019 Guidance discusses reasonable progress and the
four-factor analysis, the EPA is using the June 1, 2007 Guidance
since this is a first Planning Period action.
---------------------------------------------------------------------------
Each of the elements of the four-factor analysis is discussed
below.
A. Factor 1--The Costs of Compliance
1. EPA's Evaluation of Costs for BART in the 2012 Proposed and Final
Rule
In the 2012 proposed and final action, the EPA and Nebraska
evaluated the cost of installation of wet FGD on Gerald Gentleman
Station. Nebraska, in their SIP, concluded that these costs were
reasonable on a cost per ton basis for both units combined ($2,726/
ton).\49\ Nebraska also evaluated controls at Gerald Gentleman Station
on a dollars per dv basis.\50\ Nebraska determined that while costs on
a dollar per ton basis
[[Page 62699]]
were reasonable, costs on a dollar per dv basis were not
reasonable.\51\ Nebraska also saw water consumption of wet flue-gas
desulfurization (FGD) controls as significant and concluded that
because of this unique situation, wet FGD controls were unreasonable
for Gerald Gentleman Station Units 1 and 2.\52\
---------------------------------------------------------------------------
\49\ The Nebraska cost analysis was done using a dollar year
prior to 2012. The state analysis and the prior EPA cost analysis
were completed using a dollar year at least ten years earlier than
the cost analysis in this document. Inflation has been factored into
EPA's current cost analysis based on 2022 dollars.
\50\ As explained in the final action in 2012, the BART
Guidelines require the costs of controls to be evaluated on a dollar
per ton basis. In their BART determinations, Nebraska used a
threshold of $40 million/dv/year; in their review of the BART
analysis for Gerald Gentleman Station, the EPA concluded that
Nebraska had overestimated the cost of control and underestimated
the control efficiency of scrubbers and ignored the cumulative
visibility impacts of controls at Gerald Gentleman Station. If
Nebraska had appropriately estimated the cost of control and
considered cumulative benefits, scrubbers would have been found to
be cost effective on a dollars per deciview basis under the
threshold set by Nebraska. See 77 FR 40157.
\51\ 77 FR 12770 at 12779.
\52\ Id.
---------------------------------------------------------------------------
The EPA agreed with Nebraska that the cost per ton for FGD was
reasonable and that Nebraska's analysis showed significant visibility
improvement both at Badlands National Park and on a cumulative
basis.\53\ The EPA also found that Nebraska inappropriately ruled out
dry sorbent injection (DSI), because the EPA found that costs were
reasonable and visibility improvement was significant.\54\
---------------------------------------------------------------------------
\53\ 77 FR 12770 at 12780.
\54\ Id.
---------------------------------------------------------------------------
The EPA also found that Nebraska made several errors in determining
the cost of controls.\55\ The EPA determined that Nebraska made
incorrect assumptions about Gerald Gentleman Station's SO2
emissions and the capability of certain controls. Nebraska also
deviated from the EPA's Cost Control Manual when evaluating costs.\56\
The EPA did our own evaluation in accordance with the Cost Control
Manual and found that the cost per ton of SO2 controls
ranged from $1,972 to $2,310 for each Gerald Gentleman Station
unit.\57\ The EPA determined that the costs for control were reasonable
and visibility improvement was significant and disapproved Nebraska's
SO2 BART determination for Gerald Gentleman Station.\58\ The
EPA's partial disapproval of Nebraska's SIP was upheld by the 8th
Circuit and we are not reconsidering that decision in this proposed
rulemaking.\59\ In 2011 and 2012, neither Nebraska in their SIP
submission nor the EPA in its action analyzed whether any control
measures beyond BART were necessary to make reasonable progress at the
affected Class I areas and thus a part of Nebraska's LTS.
---------------------------------------------------------------------------
\55\ Id.
\56\ Id.
\57\ Id. This analysis and determination were conducted
consistent with previous actions where cost of control analyses were
submitted with deviations from the Control Cost Manual. 77 FR 12770
(March 2, 2012); 77 FR 40149 (July 6, 2012); 79 FR 74817 (December
26, 2014); 81 FR 295 (January 5, 2016).
\58\ Id.; 77 FR 40149.
\59\ State of Nebraska v. EPA, 812 F.3d 662 (8th Cir. 2015).
---------------------------------------------------------------------------
2. EPA's Updated Cost Evaluation
In this action, as the EPA reviewed the LTS requirements under the
CAA and its regulations, the EPA evaluated the feasibility and costs of
installing several types of SO2 control systems at Gerald
Gentleman Station. Specifically, the EPA has analyzed costs for DSI,
spray dry absorber (SDA), and wet FGD. We have looked at each of these
control technologies at various control rates to determine which rate/
control scenarios are cost effective. The cost evaluation and
methodologies are described in detail in the Cost Analysis Technical
Support Document (Cost TSD), available in the docket of this proposed
action.\60\
---------------------------------------------------------------------------
\60\ The use of the IPM cost model is consistent with the other
EPA Regional Haze actions and is based on reliable and accurate
technical tools widely utilized by the EPA to assess control
scenarios at electric generating units and other large sources.
---------------------------------------------------------------------------
In developing cost estimates for the Gerald Gentleman Station
units, we relied on the methodologies described in the EPA's Air
Pollution Control Cost Manual (the Control Cost Manual, or Manual).\61\
To estimate the costs for SDA scrubbers and wet FGD scrubbers, we used
the ``Air Pollution Control Cost Estimation Spreadsheet For Wet and Dry
Scrubbers for Acid Gas Control'' 62 63 prepared by EPA's
Office of Air Quality Planning and Standards (OAQPS) Air Economics
Group following methods in the Cost Control Manual. The methodologies
for wet FGD and SDA scrubbers are based on those from EPA's CAMPD
Integrated Planning Model (IPM) Model Version 6. To estimate the cost
for DSI, we used the 2023 version of the EPA's Retrofit Cost Analyzer
(RCA),\64\ which is an Excel-based tool that can be used to estimate
the cost of building and operating air pollution controls and also
employs Version 6 of our IPM model. These cost algorithms calculate the
Total Capital Investment (TCI) and Total Annual Direct and Indirect
Annual Costs. They also calculate the annualized costs per ton of
SO2 removed ($/ton).
---------------------------------------------------------------------------
\61\ The EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021, downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\62\ IPM Model--Updates to Cost and Performance for APC
Technologies, SDA FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy. Downloaded from https://www.epa.gov/system/files/documents/2023-03/Attachment%205-2%20SDA%20FGD%20Cost%20Development%20Methodology.pdf and https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\63\ IPM Model--Updates to Cost and Performance for APC
Technologies, Wet FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy. Downloaded from https://www.epa.gov/system/files/documents/2023-03/Attachment%205-1%20Wet%20FGD%20Cost%20Development%20Methodology.pdf and https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\64\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final March 2023, Project 13527-002,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Downloaded from https://www.epa.gov/system/files/documents/2023-04/13527-002%20DSI%20Cost%20Methodology_Final_2023.pdf and https://www.epa.gov/power-sector-modeling/retrofit-cost-analyzer.
---------------------------------------------------------------------------
The EPA evaluated the cost of DSI using the default RCA cost models
based on 2021 dollars. In order to maintain consistency with other cost
numbers presented in this proposal, we escalated these costs to the
most recent year (2022) dollars.\65\ We used the RCA Tool \66\ to
analyze the cost of DSI at Gerald Gentleman Station for SO2
emission rates of 0.10 lb/MMBtu and 0.30 lb/MMBtu. We chose these rates
based on documentation from the RCA tool. The tool does not recommend
application of DSI for SO2 emission rates below 0.10 lb/
MMBtu without unit specific analysis, and we are absent site-specific
information for Gerald Gentleman Station.\67\ As discussed in more
detail in the Cost TSD (appendix A), we are not able to find
information showing that any coal-fired units in the U.S. are currently
achieving the 0.06 lb/MMBtu rate and 0.04 lb/MMBtu rate we reviewed for
the other control options, with the use of DSI alone.
---------------------------------------------------------------------------
\65\ Ibid., p.4: ``The data was converted to 2021 dollars based
on an escalation factor of 2.5% based on the industry trends over
the last ten years (2010-2020) excluding the current market
conditions. To escalate prices from January 2021 to July 2022 costs,
an escalation factor of 19.5% should be used, based on the Handy
Whitman steam production plant index.''
\66\
\67\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final March 2023, Project 13527-002,
Eastern Research Group, Inc, Prepared by Sargent & Lundy, p.1-2.
---------------------------------------------------------------------------
The corresponding DSI control efficiency rates at Gerald Gentleman
Station Unit 1 for 0.30 lb/MMBtu and 0.10 lb/MMBtu was 52 and 84
percent SO2 removal, while Unit 2 had corresponding control
rates of 53 and 84 percent, respectively, for SO2
removal.\68\ The slight difference in control efficiency at the 0.3 lb/
MMBtu rate is due to differences in the utilization of the two units
over the time period analyzed (2018-2022). A summary of our DSI cost
analysis is shown in table 1. We conclude DSI is cost-effective at
[[Page 62700]]
$2,491/ton and $2,486/ton for Unit 1 and Unit 2, respectively at the
0.10 lb/MMBtu rate analyzed.\69\ We invite comment on the feasibility
and cost-effectiveness of the control efficiencies and emission rate
used for DSI at Gerald Gentleman Station, supported by evidence.
---------------------------------------------------------------------------
\68\ The 52-53 percent rate for DSI was selected based on easily
achieved known operating performance of installed DSI systems. The
84 percent rate for DSI was selected based on the use of milled
trona along with a baghouse. Both Gerald Gentleman Station units
have baghouses installed.
\69\ The EPA recently proposed a BART FIP for Texas that
references past BART decisions, specifically that several controls
were required by either the EPA or States as BART with average cost-
effectiveness values in the $4,200 to $5,100/ton range (escalated to
2020 dollars). In 2022 dollars, this range is $5,700/ton to $7,000/
ton. See 88 FR 28918, 28963. For 2020 the CEPCI value is 596.2. For
2022 the CEPCI value 816.0.
Table 1--DSI Costs
----------------------------------------------------------------------------------------------------------------
Removal Controlled SO2 2022$ Cost
Unit Control efficiency rate (lb/ effectiveness
(90%) MMBtu) (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit DSI (milled trona).............. 52 0.30 $2,383
1. w/BGH........................... 84 0.10 $2,491
GERALD GENTLEMAN STATION Unit DSI (milled trona).............. 53 0.30 $2,362
2. w/BGH........................... 84 0.10 $2,486
----------------------------------------------------------------------------------------------------------------
As previously mentioned, we used the ``Air Pollution Control Cost
Estimation Spreadsheet for Wet and Dry Scrubbers for Acid Gas
Control,'' to estimate the cost of SDA scrubbers. This is an Excel-
based tool that can be used to estimate the costs for installing and
operating scrubbers for reducing SO2 and acidic gas
emissions from fossil fuel-fired combustion units and other industrial
sources of acid gases.\70\ The size and costs of SDA scrubbers are
based primarily on the size of the combustion unit and the sulfur
content of the coal burned. The calculation methodologies used in the
``Air Pollution Control Cost Estimation Spreadsheet for Wet and Dry
Scrubbers for Acid Gas Control'' are consistent with those presented in
the U.S. EPA's Air Pollution Control Cost Manual. The ``Air Pollution
Control Cost Estimation Spreadsheet for Wet and Dry Scrubbers for Acid
Gas Control'' employs version 6 of our IPM model.\71\ The cost models
used in IPM version 6 were based on 2016 dollars. In performing the
cost calculations in this action,\72\ we have escalated the costs to
2022 dollars. The ``Air Pollution Control Cost Estimation Spreadsheet
for Wet and Dry Scrubbers for Acid Gas Control'' allows the user to
enter a different dollar-year for costs and the corresponding cost
index if a different dollar-year is desired. Using this capability, we
entered the 2022 Chemical Engineering Plant Cost Index (CEPCI) \73\
into the spreadsheet to estimate the cost of SDA scrubbers in 2022
dollars.
---------------------------------------------------------------------------
\70\ Air Pollution Control Cost Estimation Spreadsheet for Wet
and Dry Scrubbers for Acid Gas Control, U.S. Environmental
Protection Agency, Air Economics Group, Health and Environmental
Impacts Division, Office of Air Quality Planning and Standards
(January 2023), downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\71\ Documentation for EPA's Power Sector Modeling Platform v6
Using the Integrated Planning Model, dated March 2023. Documentation
for v6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-post-ira-2022-reference-case.
\72\ Spreadsheets containing our cost calculations are located
in our Docket.
\73\ http://www.chemengonline.com/pci-home.
---------------------------------------------------------------------------
We evaluated the cost of SDA using a control efficiency rate of 90
and 91 percent SO2 removal at Gerald Gentleman Station Units
1 and 2, corresponding to an SO2 emission rate of 0.06 lb/
MMBtu at both Units. The EPA analyzed the cost of SDA scrubbers using
this removal rate and emission limit because the lowest available
SO2 emission guarantees from original equipment
manufacturers of SDA systems are 0.06 lb/MMBtu. A summary of our SDA
scrubber cost analysis is shown in table 2. We conclude SDA scrubbers
are cost-effective at $4,073/ton and $4,002/ton for Unit 1 and Unit 2,
respectively at the 0.06 lb/MMBtu rate analyzed.\74\
---------------------------------------------------------------------------
\74\ The EPA recently proposed a BART FIP for Texas that
references past BART decisions, specifically that several controls
were required by either the EPA or States as BART with average cost-
effectiveness values in the $4,200 to $5,100/ton range (escalated to
2020 dollars). In 2022 dollars, this range is $5,700/ton to $7,000/
ton. See 88 FR 28918, 28963. For 2020 the CEPCI value is 596.2. For
2022 the CEPCI value 816.0.
Table 2--SDA Costs
----------------------------------------------------------------------------------------------------------------
Controlled SO2 2022$ Cost
Unit Control Removal Rate (lb/ effectiveness
efficiency (%) MMBtu) (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit SDA............................. 90 0.06 $4,073
1.
GERALD GENTLEMAN STATION Unit SDA............................. 91 0.06 4,002
2.
----------------------------------------------------------------------------------------------------------------
The cost of a baghouse to collect the particles from the operation
of the SDA scrubbers was not included in our cost estimate because
Gerald Gentleman Station currently operates a baghouse on both units.
The EPA invites comment on the feasibility and cost-effectiveness of a
higher control efficiency, and lower emission rate, using dry scrubbing
at Gerald Gentleman, supported by evidence.
We also evaluated the cost of a wet FGD at Gerald Gentleman Station
Units 1 and 2. The size and costs of wet FGD scrubbers are based
primarily on the size of the combustion unit and the sulfur content of
the coal burned. The wet FGD scrubber cost methodology includes cost
algorithms for capital and operating cost for wastewater treatment
consisting of chemical pretreatment, low hydraulic residence time
biological reduction, and ultrafiltration to treat wastewater generated
by the wet FGD system.\75\
---------------------------------------------------------------------------
\75\ The methodologies had not been updated to incorporate the
May 9, 2024 Steam Electric Power Generation Effluent Limitation
Guidelines and Standards.
---------------------------------------------------------------------------
Similar to our SDA analysis and approach, the cost models used in
IPM version 6 were based on 2016 dollars and we escalated the costs to
2022
[[Page 62701]]
dollars to estimate the cost of wet FGD scrubbers in 2022 dollars. As
shown in table 3, the EPA used SO2 control efficiencies of
90-91 percent and 94 percent corresponding to emission rates of 0.06
and 0.04 lb/MMBtu, respectively.\76\ We conclude wet FGD are cost-
effective at $4,283/ton and $4,145/ton for Unit 1 at 90% and 94%
SO2 removal rate (respectively) and $4,267/ton and $4,132/
ton for Unit 2 at 91% and 94% SO2 removal rate
(respectively).
---------------------------------------------------------------------------
\76\ The EPA analyzed the cost of wet scrubbers based on limits
of 0.04 and at 0.06 lb/MMBtu. The first analysis at 0.04 lb/MMBtu
evaluates wet FGD which is the lowest rate that vendors of the
technology will guarantee. The IPM presumptive control model uses a
removal efficiency of 98 percent. Because a 98 percent removal
efficiency results in SO2 rates less than 0.04 lb/MMBtu
for the Gerald Gentleman Station units, we limited the control
efficiency in the cost algorithm to just under 94 percent to assure
that NPPD can obtain a performance guarantee for the wet scrubber.
The second analysis allows direct comparison to SDA at similar
reduction efficiencies of 90- 91 percent.
Table 3--Wet FGD Costs
----------------------------------------------------------------------------------------------------------------
Controlled SO2 2022$ Cost
Unit Control Removal Rate (lb/ effectiveness
efficiency (%) MMBtu) (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit Wet FGD......................... 90 0.06 $4,283
1. 94 0.04 4,145
GERALD GENTLEMAN STATION Unit Wet FGD......................... 91 0.06 4,267
2. 94 0.04 4,132
----------------------------------------------------------------------------------------------------------------
We acknowledge that the remaining useful life affects the cost
effectiveness estimates for the control technologies analyzed in this
section. As discussed in more detail in appendix A of the TSD,
available in the docket of this proposal, and in section IV.A.4. below,
the EPA has used 30 years as the remaining useful life of the units and
any new controls installed on them. The EPA believes that even if the
remaining useful life of the units is as short as 20 years, the
proposed control rate and associated control technologies are still
cost effective.
Based on our assessment, we are concluding that cost effective
controls of SO2 are available using DSI, SDA scrubbers and
wet FGD scrubbers.
B. Factor 2--The Time Necessary for Compliance
The EPA believes five years is the appropriate time period for
installation of wet FGD or SDA except where there are unusual
circumstances. Five years for installation is consistent with our
experience regarding FGD installations at power plants generally. In
response to a section 114 information request, NPPD submitted several
documents that demonstrate that between 2009 and 2014, NPPD considered
installing wet FGD controls on Gerald Gentleman Station Units 1 and
2.\77\ The engineering documents and requests for bids from this
process included a timeline of five years from design to completion.
The EPA believes this is an appropriate timeframe for installation of
wet FGD controls at Gerald Gentleman Station. We believe that SDA could
be installed within the same timeframe. DSI may be able to be installed
in a time frame of two to three years. This is consistent with the
previous EPA actions.\78\
---------------------------------------------------------------------------
\77\ See NPPD CAA section 114 Response: NPPDRH114_0000892,
NPPDRH114_0001321, NPPDRH114_0001584, NPPDRH114_0002059,
NPPDRH114_0005017.
\78\ See 76 FR 81729, 81758 (December 28, 2011) and 81 FR 66332,
66416 (September 27, 2016), where we promulgated regional haze FIPs
for Oklahoma and Arkansas, respectively. These FIPs required BART
SO2 emission limits on coal-fired EGUs based on new
scrubber retrofits with a compliance date of no later than five
years from the effective date of the final rule. Also see 88 FR
28918 (May 4, 2023), where we proposed BART SO2 emission
limits with a compliance date not later than three years or DSI and
five years for wet FDG.
---------------------------------------------------------------------------
C. Factor 3--The Energy and Non-Air Quality Environmental Impacts of
Compliance
The Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program advises, ``In assessing energy impacts, you may
want to consider whether the energy requirements associated with a
control technology result in energy penalties.'' ``To the extent that
these considerations are quantifiable they should be included in the
engineering analyses supporting compliance cost estimates'', and to
consult the BART Guidelines.\79\ To analyze energy impacts, the BART
Guidelines advise, ``You should examine the energy requirements of the
control technology and determine whether the use of that technology
results in energy penalties or benefits.'' \80\ As discussed above in
our cost analyses for DSI, SDA, and wet FGD, our cost model allows for
the cost of additional auxiliary power required for pollution controls
to be included in the variable operating costs. The EPA chose to
include this additional auxiliary power in all cases. Further, the cost
of electricity is negligible compared to the capacity of Gerald
Gentleman Station and the grid as a whole. For WFGD, the cost of
electricity is approximately 1.25% of energy output. For SDA, the cost
of electricity is approximately 1.32% of energy output. For DSI, the
cost of electricity is 0.28% of energy output. Consequently, we believe
that any energy impacts of compliance have been adequately considered
in our analyses.
---------------------------------------------------------------------------
\79\ Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program, June 1, 2007, available at https://www3.epa.gov/ttn/naaqs/aqmguide/collection/cp2/20070601_wehrum_reasonable_progress_goals_reghaze.pdf.
\80\ 70 FR 39168 (July 6, 2005).
---------------------------------------------------------------------------
The Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program also advises the consideration of ``the effects
of the waste stream that may be generated by a particular control
technology, and/or other resource consumption rates such as water,
water supply, and wastewater disposal. To the extent that these
considerations are quantifiable, they should also be included in the
analyses supporting compliance cost estimates'' and to also consult the
BART Guidelines for additional guidance on applying this factor to
stationary sources.\81\ Regarding the analysis of non-air quality
environmental impacts, the BART Guidelines advise ``Such environmental
impacts include solid or hazardous waste generation and discharges of
polluted water from a control device. You should identify any
significant or unusual environmental impacts associated with a control
alternative that have the potential to affect the selection or
elimination of a control alternative. Some control technologies may
have potentially significant secondary environmental impacts. Scrubber
effluent, for example, may affect water quality or land use.
Alternatively, water availability may affect the feasibility
[[Page 62702]]
and costs of wet FGD. Other examples of secondary environmental impacts
could include hazardous waste discharges, such as spent catalysts or
contaminated carbon. Generally, these types of environmental concerns
become important when sensitive site-specific receptors exist, or when
the incremental emission reductions potential of the more stringent
control is only marginally greater than the next most-effective option.
However, the fact that a control device creates liquid and solid waste
that must be disposed of does not necessarily argue against selection
of that technology as BART, particularly if the control device has been
applied to similar facilities elsewhere and the solid or liquid waste
is similar to those other applications. On the other hand, where you or
the source owner can show that unusual circumstances at the proposed
facility create greater problems than experienced elsewhere, this may
provide a basis for the elimination of that control alternative as
BART.'' \82\
---------------------------------------------------------------------------
\81\ Id.
\82\ 70 FR 39169 (July 6, 2005).
---------------------------------------------------------------------------
The SO2 control technologies the EPA considered in our
analyses--DSI, SDA, and wet FGD--are in wide use in the coal-fired
electricity generation industry. All three technologies would add spent
reagent to the waste stream already generated by Gerald Gentleman
Station, but do not present any unusual environmental waste impacts. In
the case of DSI, the use of sodium-based sorbents makes fly ash
unsaleable. The EPA has calculated that this would result in revenue
loss of approximately $0.07/MWh ($1/ton fly ash estimate converted to
$/MWh) and additional disposal costs of approximately $2/MWh. As
discussed in our cost analyses for DSI, SDA, and wet FGD, our cost
model includes waste disposal costs in the variable operating costs.
Non-air environmental impacts may also take into account water use
to operate to the SO2 controls evaluated, in particular wet
FGD scrubbers. While the cost of incorporating a wastewater treatment
facility at Gerald Gentleman Station is factored into our cost analysis
for Wet FGD, we recognize water quality concerns associated with the
waste stream for wet FGD as compared to the installation of SDA
scrubbers and DSI. The wet FGD scrubber methodology includes cost
algorithms for capital and operating cost for wastewater treatment
consisting of chemical pretreatment, low hydraulic residence time
biological reduction, and ultrafiltration to treat wastewater generated
by the wet FGD system. The calculation methodologies used in the ``Air
Pollution Control Cost Estimation Spreadsheet for Wet and Dry Scrubbers
for Acid Gas Control,'' are those presented in the U.S. EPA's Air
Pollution Control Cost Manual.
The cost algorithm used in the ``Air Pollution Control Cost
Estimation Spreadsheet for Wet and Dry Scrubbers for Acid Gas Control''
calculates the Total Capital Investment, Direct Annual Cost, and
Indirect Annual Cost. The Total Capital Investment for wet FGD is a
function of the absorber island capital costs, reagent preparation
equipment costs, waste handling equipment costs, balance of plant
costs, and wastewater treatment facility costs.
Regarding water related impacts, we recognize that wet FGD requires
additional amounts of water as compared to SDA and DSI. Furthermore,
based on Effluent Limitation Guidelines (ELG), it is expected that all
future wet FGD installations will require the facility to incorporate a
wastewater treatment facility.\83\ While this cost is factored into our
cost analysis, it also highlights water quality concerns associated
with the waste stream for wet FGD as compared to the installation of
dry scrubbers and DSI.
---------------------------------------------------------------------------
\83\ IPM Model--Updates to Cost and Performance for APC
Technologies, Wet FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy, p. 1. This Model is prior to the May 9, 2024 Steam
Electric Power Generation Effluent Limitation Guidelines and
Standards.
---------------------------------------------------------------------------
Gerald Gentleman Station is located in western Nebraska, a semi-
arid region dominated by agriculture. While we are aware of water
availability concerns in the area surrounding Gerald Gentleman Station,
we believe water resources are available to operate all control
technologies evaluated in our cost analysis. This is based on
Nebraska's Regional Haze SIP, the record for our previous actions on
Nebraska's SIP, and information obtained from NPPD in 2017, which
contain extensive information about water availability in the area of
Gerald Gentleman Station. In our 2012 action, the EPA found that the
cost of purchasing additional water at $234 per ton of SO2
and that this cost was reasonable.\84\
---------------------------------------------------------------------------
\84\ 77 FR 33642 (June 7, 2012). Note we are not using this
number in our current cost analysis.
---------------------------------------------------------------------------
D. Factor 4--The Remaining Useful Life of the Source
The Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program advises, ``If the remaining useful life of the
source will clearly exceed'' the standard time period listed in the EPA
Air Pollution Control Cost Manual, ``the remaining useful life factor
has essentially no effect on control costs and on the reasonable
progress determination process. Where the remaining useful life of the
source is less than the time period for amortizing the costs of the
retrofit control, you may wish to use this shorter time period in your
cost calculations. For additional guidance on applying this factor to
stationary sources, you may wish to consult the BART Guidelines''.\85\
Regarding the analysis of remaining useful life, the BART Guidelines
advise ``The ``remaining useful life'' of a source, if it represents a
relatively short time period, may affect the annualized costs of
retrofit controls. For example, the methods for calculating annualized
costs in EPA's OAQPS Control Cost Manual requires the use of a
specified time period for amortization that varies based upon the type
of control. If the remaining useful life will clearly exceed this time
period, the remaining useful life essentially has no effect on control
costs and on the BART determination process. Where the remaining useful
life is less than the time period for amortizing costs, you should use
the shorter time period in your cost calculations.'' \86\
---------------------------------------------------------------------------
\85\ Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program, June 1, 2007.
\86\ 70 FR 39168 (July 6, 2005).
---------------------------------------------------------------------------
In determining the cost of scrubbers in the original SIP
submission, Nebraska did not provide a specific useful life for the
Gerald Gentleman Station.\87\ NPPD also did not provide additional
insight regarding the remaining useful life of the Gerald Gentleman
Station in their section 114 response from 2016. Therefore, in line
with the EPA's approach in prior actions,\88\ we used 30 years in the
cost module of the IPM model when calculating costs for scrubber
controls at the Gerald Gentleman Station in this action.
---------------------------------------------------------------------------
\87\ ``The useful remaining life of Gerald Gentleman Station
Units 1 and 2 is greater than 20 years under the current NPPD energy
resource plan. Therefore, the remaining useful life has no impact on
the annualized estimated control technology cost at this time.''
Nebraska Regional Haze SIP, section 10.6.4.9.
\88\ See 76 FR 52388 (August 22, 2011); 76 FR 81728 (December
28, 2011); Oklahoma v. EPA, 723 F.3d 1201 (July 19, 2013), cert.
denied (U.S. May 27, 2014).
---------------------------------------------------------------------------
Similarly, the EPA sees no reason to assume that a DSI system
installation, which is a much less complex and costly (capital costs,
as opposed to annualized costs) technology in comparison to a scrubber
installation, should have a shorter lifetime. As with a wet FGD or SDA,
we expect the boiler to be the limiting factor when considering the
lifetime of a coal-fired power plant. The EPA has therefore
[[Page 62703]]
similarly assumed that the lifetime of a DSI system is 30 years.
When considering the remaining useful life of a source, we must
consider the useful life of any additional controls we could require
and the remaining useful life of the source itself. All the examined
control options have useful lives of 30 years, therefore, we propose to
conclude that Units 1 and 2 have a remaining useful life of 30 years.
In the NPPD 2023 Integrated Resource Plan, NPPD analyzed several
continued operation scenarios. In the ``SD-05'' scenario, Gerald
Gentleman Station continues to operate as is until at least 2050.\89\
While NPPD has indicated a possible shortening of its EGUs' lifespans,
including Gerald Gentleman Station, NPPD has also indicated continued
operation of Gerald Gentleman Station. Without a federally enforceable
shutdown included in the SIP, the EPA must conclude that NPPD will
continue operating Gerald Gentleman Station and must use the 30-year
lifetime in the EPA cost analyses.
---------------------------------------------------------------------------
\89\ See ``NPPD2023IntergratedResourcePlan.pdf'' in the docket
for this action.
---------------------------------------------------------------------------
E. Evaluation of Potential Visibility Impacts and Improvements
Although visibility is not a required element of the four-factor
analysis, we reviewed the visibility information from the original
Nebraska Regional Haze SIP record to verify the impacts of Gerald
Gentleman Station on the nearest Class I areas of Badlands, Wind Cave,
and Rocky Mountain National Parks. In addition, we provide an updated
meteorological back-trajectory analysis on the 20% most impaired
monitored days for the period from 2008 through 2021 at Badlands, Wind
Cave and Rocky Mountain Class I areas in our Analysis and Modeling TSD,
which is included in the docket. In this back-trajectory analysis, we
run 72-hour HYSPLIT model back-trajectories originating at Class I area
at three different height levels (100 meters, 500 meters and 1,000
meters). We created composite HYSPLIT density plots for multi-year
periods and the plots show a consistent pattern of the air mass over or
near the location of Gerald Gentleman Station on the 20% most impaired
days for the Badlands and Wind Cave Class I areas. We also generated
daily back trajectory plots accompanied by plots of Gerald Gentleman
Station SO2 emissions data and show that Gerald Gentleman
Station was operating and emitting SO2 on, or leading up to,
the most impaired days when back trajectories traveled near Gerald
Gentleman Station.
In summary, we confirmed the CENRAP and Nebraska CALPUFF modeling
associated with Nebraska's first planning period SIP, and our updated
back-trajectory analysis shows that Gerald Gentleman Station likely
impacts the visibility at the affected Class I areas. Please see our
Analysis and Modeling TSD for the detailed analysis linking emissions
from Gerald Gentleman Station to visibility impairment at nearby Class
I areas.
Both the CENRAP and WRAP CAMx modeling and BART CALPUFF modeling
relied upon in the Nebraska's first planning period SIP indicate a
visibility improvement with the installation of SO2 controls
at Gerald Gentleman Station. The projected 2018 modeling shows
improvements in the visibility impairment contribution from Nebraska
elevated sources at Badlands due to decreases in emissions from the
SO2 BART controls assumed at Gerald Gentleman Station in the
modeling. CALPUFF modeling with either wet FGD or DSI at a control rate
of 0.15 lb/MMBtu produced significant visibility improvements at the
two South Dakota Class I areas and Rocky Mountain National Park when
averaged over the 2001-2003 modeling period. All control options with
this level of control rate or lower will achieve significant emission
reductions and visibility improvements, with lower control rates (i.e.,
below the modeled 0.15 lb/MMBtu) leading to greater visibility
improvement.
Therefore, although visibility is not a required element of the
four-factor analysis, we propose to conclude there will be significant
visibility benefit to the Class I areas as a result of installation of
cost-effective SO2 controls at Gerald Gentleman Station.
VI. Amending the FIP on Remand--Long-Term Strategy Determination for
Gerald Gentleman Station
In light of the significant emission reductions achieved by a 0.06
lb/MMBtu SO2 emission limit, leading to significant
visibility improvements, the proven ability of both FGD and SDA to
achieve a rate of 0.06 lb/MMBtu SO2 consistently over a long
period of time, the controls being cost effective, the ability to
reasonably obtain water to operate controls, the lower amount of
wastewater generated, and the lack of certainty surrounding DSI being
able to achieve the proposed limit at Gerald Gentlemen Station, to
address the remand for LTS for SO2 at Gerald Gentleman
Station, the EPA is proposing that Gerald Gentleman Station Unit 1 and
Unit 2 meet an SO2 emission limit of 0.06 lb/MMBtu averaged
over a rolling 30 boiler-operating-day period for each unit.\90\
---------------------------------------------------------------------------
\90\ A boiler operating day is any 24-hour period between 12:00
midnight and the following midnight during which any fuel is
combusted at any time at the steam generating unit.
---------------------------------------------------------------------------
Further, the EPA notes that all SO2 control technologies
analyzed in this action are cost effective at all analyzed control
percentages. While a 0.06 lb/MMBtu SO2 limit would achieve a
high level of visibility improvement, the EPA nonetheless acknowledges
that all the emission control technologies evaluated in this action
will reduce SO2 emissions, thus resulting in improved
visibility at the affected Class I areas.
The EPA also notes that all the SO2 control technologies
discussed in this action can be installed within 5 years and DSI can be
installed as quickly as two years. Therefore, the time necessary for
compliance for all emission rates can be considered equivalent and
reasonable.
In considering the relevant energy and nonair environmental
concerns, the cost of electricity is negligible compared to the
capacity of Gerald Gentleman Station and the grid as a whole, as
included in our cost analysis. Additionally, more waste will be
generated but not at a rate that would be considered unusual or
unreasonable. The EPA notes that DSI and SDA generate less wastewater
than wet FDG, for the same emission limit. Finally, while there is
water scarcity in the region, NPPD has access to water to operate the
controls and water costs are included in our cost analysis.
The EPA also proposes to find that there are no permanent and
enforceable limitations on the continued operation of Gerald Gentleman
Station. The EPA is therefore proposing that the remaining useful life
of the source is at least thirty years.
Therefore, we also invite comment on all the control technologies
and other emission limits analyzed within this action. The EPA is
choosing to propose an SO2 emission limit of 0.06 lb/MMBtu
based on multiple factors outlined at the beginning of this section.
This limit was selected based on the operation of SDA. We find SDA can
meet the 0.06 lb/MMBtu limit at a reasonable, cost-effective level and
will result in large emissions reductions and visibility improvements
with less water usage and wastewater than wet FGD. As discussed in more
detail in the Cost TSD (Appendix A), we are not able to find
information showing that any coal-fired units in the U.S. are currently
meeting the 0.06 lb/MMBtu rate limit proposed in this action with the
use of DSI alone.
[[Page 62704]]
Therefore, we do not have a sufficient basis to conclude that DSI can
be used to meet a 0.06 lb/MMBtu limit at Gerald Gentleman Station.
However, the EPA's analysis shows that NPPD can achieve this emission
rate utilizing SDA or wet FGD technology, both of which are cost-
effective based on the EPA's analysis outlined throughout this action.
Therefore, rather than proposing a specific control technology, the EPA
believes it is appropriate to only propose an emission limit because it
may be possible to meet the proposed limit with SDA or FGD. As stated
above, we do not have sufficient information to determine whether DSI
can meet this limit on a consistent, long-term basis. By proposing a
limit only, the EPA is providing the source with greater flexibility to
select the control technology that best meets its needs while also
providing emissions reductions which will result in visibility benefits
at the affected Class I areas.
VII. The EPA's FLM Consultation
The EPA consulted with the FLMs (specifically, U.S. Fish and
Wildlife Service, U.S. Forest Service, and the National Park Service)
on April 23, 2024 to May 10, 2024. During the consultation we provided
an overview of our proposed actions and drafts of our technical support
documents. The FLMs signaled general support for our action.
VIII. Proposed Action
Based on the EPA's review of the LTS requirements along with its
analysis of the four statutory factors, the EPA proposes that NPPD
Gerald Gentleman Station Unit 1 and Unit 2 each meet an emission limit
of 0.06 lb/MMBtu averaged over a rolling 30 boiler-operating-day
period. This emission limit would apply at all times, including periods
of startup and shut down. We are also taking comment on the other
control technologies and emissions limits analyzed in this action.
IX. Environmental Justice Considerations
This section summarizes environmental justice data for areas that
would be impacted by this proposed action and is intended for
informational and transparency purposes only. Whereas, environmental
justice data is not a key determinate for this action, the CAA and
applicable implementing regulations neither prohibit nor require an
evaluation of environmental justice. This action is perceived to have a
positive benefit on environmental justice areas. The EPA defines
environmental justice (EJ) as ``the fair treatment and meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies.'' The EPA
further defines the term fair treatment to mean that ``no group of
people should bear a disproportionate burden of environmental harms and
risks, including those resulting from the negative environmental
consequences of industrial, governmental, and commercial operations or
programs and policies.'' \91\ Recognizing the importance of these
considerations to local communities, the EPA conducted an environmental
justice screening analysis around the location of Gerald Gentleman
Station to identify potential environmental stressors on these
communities and the potential impacts of this action. However, the EPA
is providing the information associated with this analysis for
informational purposes only. The information provided herein is not a
basis of the proposed action. The EPA conducted the screening analyses
using EJScreen, an EJ mapping and screening tool that provides the EPA
with a nationally consistent dataset and approach for combining various
environmental and demographic indicators.\92\ The EJScreen tool
presents these indicators at a Census block group (CBG) level or a
larger user specified ``buffer'' area that covers multiple CBGs.\93\ An
individual CBG is a cluster of contiguous blocks within the same census
tract and generally contains between 600 and 3,000 people. EJScreen is
not a tool for performing in depth risk analysis, but is instead a
screening tool that provides an initial representation of indicators
related to EJ and is subject to uncertainty in some underlying data
(e.g., some environmental indicators are based on monitoring data which
are not uniformly available; others are based on self-reported
data).\94\ EJScreen environmental indicators help screen for locations
where residents may experience a higher overall pollution burden than
would be expected for a block group with the same total population in
the U.S. These indicators of overall pollution burden include estimates
of ambient particulate matter (PM2.5) and ozone
concentration, a score for traffic proximity and volume, percentage of
pre-1960 housing units (lead paint indicator), and scores for proximity
to Superfund sites, risk management plan (RMP) sites, and hazardous
waste facilities.\95\ EJScreen also provides information on demographic
indicators, including percent low-income, communities of color,
linguistic isolation, and less than high school education. The EPA
prepared an EJScreen report covering a buffer area of approximately 6-
mile radius around Gerald Gentleman Station. From this report, no EJ
indices were greater than the 80th national percentiles.\96\ The full,
detailed EJScreen report is provided in the docket for this rulemaking.
This action is proposing to promulgate a FIP to address LTS
requirements that are not adequately satisfied by the Nebraska Regional
Haze SIP. The proposed rule is proposing SO2 limits on
Gerald Gentleman Station in Nebraska to fulfill regional haze program
requirements. Exposure to SO2 is associated with significant
public health effects. Short-term exposures to SO2 can harm
the human respiratory system and make breathing difficult. People with
asthma, particularly children, are sensitive to these effects of
SO2.\97\ Therefore, we expect that these requirements for
Gerald Gentleman Station in Nebraska, if finalized, and resulting
emissions reductions will contribute to reduced environmental and
health impacts on all populations impacted by emissions from these
sources, including populations experiencing a higher overall pollution
burden, people of color and low-income populations. There is nothing in
the record which indicates that this proposed action, if finalized,
would have disproportionately high or adverse human health or
environmental effects
[[Page 62705]]
on communities with environmental justice concerns.
---------------------------------------------------------------------------
\91\ See https://www.epa.gov/environmentaljustice/learn-about-environmentaljustice.
\92\ The EJSCREEN tool is available at https://www.epa.gov/ejscreen.
\93\ See https://www.census.gov/programssurveys/geography/about/glossary.html.
\94\ In addition, EJSCREEN relies on the five-year block group
estimates from the U.S. Census American Community Survey. The
advantage of using five-year over single-year estimates is increased
statistical reliability of the data (i.e., lower sampling error),
particularly for small geographic areas and population groups. For
more information, see https://www.census.gov/content/dam/Census/library/publications/2020/acs/acs_general_handbook_2020.pdf.
\95\ For additional information on environmental indicators and
proximity scores in EJSCREEN, see ``EJSCREEN Environmental Justice
Mapping and Screening Tool: EJSCREEN Technical Documentation,''
Chapter 3 and Appendix C (September 2019) at https://www.epa.gov/sites/default/files/2021-04/documents/ejscreen_technical_document.pdf.
\96\ For a place at the 80th percentile nationwide, that means
20% of the U.S. population has a higher value. The EPA identified
the 80th percentile filter as an initial starting point for
interpreting EJScreen results. The use of an initial filter promotes
consistency for the EPA programs and regions when interpreting
screening results.
\97\ See https://www.epa.gov/so2-pollution/sulfur-dioxide-basics#effects.
---------------------------------------------------------------------------
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 14094: Modernizing Regulatory Review
This action is exempt from review under Executive Order 12866, as
amended by Executive Order 14094, because it is not a ``significant
regulatory action'' under the terms of Executive Order 12866 \98\ and
is therefore not subject to review under Executive Orders 12866 and
14094.\99\ The proposed FIP only applies to one facility. It is
therefore not a rule of general applicability.
---------------------------------------------------------------------------
\98\ 58 FR 51735 (October 4, 1993).
\99\ 88 FR 21879 (April 11, 2023).
---------------------------------------------------------------------------
B. Paperwork Reduction Act
This proposed action does not impose an information collection
burden under the provisions of the Paperwork Reduction Act because it
is not a rule of general applicability and affects fewer than 10
entities. See 5 CFR 1320(c).
C. Regulatory Flexibility Act
I certify that this action will not have a significant impact on a
substantial number of small entities. This proposed rule does not
impose any requirements or create impacts on small entities. Nebraska
Public Power District is not a small entity.
D. Unfunded Mandates Reform Act (UMRA)
This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for state, local, or tribal governments or the private
sector. The EPA has determined that Title II of UMRA does not apply to
this proposed rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA
have the meanings set forth in 2 U.S.C. 658, which further provides
that the terms ``regulation'' and ``rule'' have the meanings set forth
in 5 U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not
include a rule of particular applicability relating to . . .
facilities.'' Because this proposed rule is a rule of particular
applicability relating to specific EGUs located at one named facility,
the EPA has determined that it is not a ``rule'' for the purposes of
Title II of UMRA.
E. Executive Order 13132: Federalism
This action does not have Federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. This
proposed rule does not impose significant economic costs on state or
local governments. Thus, Executive Order 13132 does not apply to this
proposed action. In the spirit of Executive Order 13132, and consistent
with the EPA policy to promote communications between the EPA and state
and local governments, the EPA specifically solicits comment on this
proposed rule from state and local officials.
F. Executive Order 13175: Coordination With Indian Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. This action applies to one facility in Nebraska
and will affect Federal Class I areas in South Dakota and Colorado.
This action does not apply on any Indian reservation land or any other
areas where the EPA or an Indian tribe has demonstrated that a tribe
has jurisdiction, or non-reservation areas of Indian county. Thus
Executive Order 13175 does not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045: Protection from Environmental Health Risks
and Safety Risks applies to any rule that: (1) is determined to be
economically significant as defined under Executive Order 12866; and
(2) concerns an environmental health or safety risk that we have reason
to believe may have a disproportionate risk to children. Moreover,
``regulation'' or ``rule'' is defined in Executive Order 12866 as ``an
agency statement of general applicability and future effect.'' E.O.
12866 does not define ``statement of general applicability'' but this
term commonly refers to statements that apply to groups or classes, as
opposed to statements which apply only to named entities. The proposed
FIP, therefore, is not a rule of general applicability because its
requirements apply and are tailored to only one individually identified
facility. Thus it is not a ``rule'' or ``regulation'' within in the
meaning of E.O. 12866. However, as this action will limit emissions of
SO2, it will have a beneficial effect on children's health
by reducing air pollution.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution or Use
This proposed action is not subject to Executive Order 13211
because it is not a significant regulatory action under Executive Order
12866.
I. National Technology Transfer Advancement Act
This proposed action involves technical standards. Section 12(d) of
the National Technology Transfer and Advancement Act of 1995
(``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs the
EPA to use voluntary consensus standards in its regulatory activities,
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs the EPA to provide Congress,
through OMB, explanations when the Agency decides not to us available
and applicable voluntary consensus standards. This proposed rule would
require the affected facility to meet the applicable monitoring
requirements of 40 CFR part 75. Part 75 already incorporates a number
of voluntary consensus standards. Consistent with the Agency's
Performance Based Measurement (PBMS), part 75 sets forth performance
criteria that allow the use of alternative methods to the ones set
forth in part 75. The PBMS approach is intended to be more flexible and
cost-effective for the regulated community; it is also intended to
encourage innovation in analytical technology and improved data
quality. At this time, the EPA is not recommending any revisions to
part 75; however, the EPA periodically revises the test procedures set
forth in part 75. When the EPA revises the test procedures set forth in
part 75 in the future, the EPA will address the use of any new
voluntary consensus standards that are equivalent. Currently, even if a
test procedure is not set forth in part 75, the EPA is not precluding
the use of any method, whether it constitutes a voluntary consensus
standard or not, as long as it meets the performance criteria
specified; however any alternative methods must be approved through the
petition process under 40 CFR 75.66 before they are used.
[[Page 62706]]
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations and
Executive Order 14096: Revitalizing Our Nation's Commitment to
Environmental Justice for All
The EPA believes that the human health and environmental
conditions, around Gerald Gentelman Station, that exist prior to this
action do not result in disproportionate and adverse effects on
communities with Environmental Justice concerns.
The EPA believes that this action is not likely to result in new
disproportionate and adverse effects on communities with environmental
justice concerns. This proposed FIP limits emissions of SO2
from one facility in Nebraska.
The information supporting this Executive Order review is contained
in Section IX Environmental Justice Considerations of this action and
the file GGS6mileEJScreen Community Report.pdf in the docket for this
action.
The EPA believes the human health or environmental risk addressed
by this proposed action will not have potential disproportionately high
and adverse human health or environmental effects on communities with
environmental justice concerns because it increases the level of
environmental protection for all affected populations without having
any disproportionately high and adverse human health or environmental
effects on any population, including any communities with environmental
justice concerns.
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Interstate transport of
pollution, Nitrogen dioxide, Ozone, Particulate matter, Regional haze,
Reporting and recordkeeping requirements, Sulfur oxides, Visibility.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, the EPA proposes to amend
40 CFR part 52 as set forth below:
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart CC--Nebraska
0
2. Amend Sec. 52.1437 by revising paragraph (b) and adding paragraph
(c) to read as follows:
Sec. 52.1437 Visibility protection.
* * * * *
(b) Measures addressing partial disapproval associated with
SO2. The deficiencies associated with the SO2
BART determination for NPPD, Gerald Gentleman Station, Units 1 and 2
identified in EPA's partial disapproval of the regional haze plan
submitted by Nebraska on July 13, 2011, are satisfied by Sec. 52.1429.
The deficiencies associated with the SO2 LTS addressing
SO2 emissions for NPPD, Gerald Gentleman Station, Units 1
and 2 identified in EPA's partial disapproval of the regional haze plan
submitted by Nebraska on July 13, 2011, are satisfied by paragraph (c)
of this section.
(c) Requirements for Gerald Gentleman Station Units 1 and 2
affecting visibility.
(1) Applicability. The provisions of this section shall apply to
each owner, operator, or successive owners or operators of the coal
burning equipment designated as Gerald Gentleman Station Units 1 and 2.
(2) Compliance dates. Compliance with the requirements of this
section is required by 5 years from the effective date of this rule for
Gerald Gentleman Station Units 1 and 2.
(3) Definitions. All terms used in this part but not defined herein
shall have the meaning given to them in the Clean Air Act and in parts
51 and 60 of this title. For the purposes of this section:
24-hour period means the period of time between 12:01 a.m. and 12
midnight.
Air pollution control equipment includes baghouses, particulate or
gaseous scrubbers, sorbent injection systems, and any other apparatus
utilized to control emissions of regulated air contaminants which would
be emitted to the atmosphere.
Boiler-operating-day means any 24-hour period between 12:00
midnight and the following midnight during which any fuel is combusted
at any time in a steam generating unit.
Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the coal burning equipment designated in
paragraph (a) of this section.
Regional Administrator means the Regional Administrator of Region 7
or his/her authorized representative.
Unit means each individual coal-fired boiler covered under
paragraph (a) of this section.
(4) Emissions limitations. SO2 emission limit. The
owner/operator of the units listed below shall not emit or cause to be
emitted pollutants in excess of the following limitations in pounds per
million British thermal units (lb/MMBtu) as averaged over a rolling 30
boiler-operating-day period from the subject unit. Compliance with the
requirements of this section is required as listed below. The sulfur
dioxide (SO2) emission limit for each individual unit shall
be as listed in the following table.
------------------------------------------------------------------------
SO2 Emission limit
Unit (lbs/MMBtu) Compliance date
------------------------------------------------------------------------
Gerald Gentleman Station Unit 0.06 Five years from
1. effective date of
the final rule.
Gerald Gentleman Station Unit 0.06 Five years from
2. effective date of
the final rule.
------------------------------------------------------------------------
(5) Testing and monitoring.
(i) No later than the compliance date of this regulation, the owner
or operator shall install, calibrate, maintain and operate Continuous
Emissions Monitoring Systems (CEMS) for SO2, diluent
(%CO2 or %O2) and flow, for each unit listed in
section (1) in accordance with 40 CFR 60.8 and 60.13 (e), (f), and (h),
and appendix B of part 60. The owner or operator shall comply with the
quality assurance procedures for CEMS found in 40 CFR part 75. The
SO2, diluent, and flow CEMS data, expressed in units of the
standard, shall be used to verify compliance for each unit.
[[Page 62707]]
(ii) Continuous emissions monitoring shall apply during all periods
of operation of the coal burning equipment including periods of
startup, shutdown, and malfunction, except for CEMS breakdowns,
repairs, calibration checks, and zero and span adjustments. Continuous
monitoring systems for measuring SO2 and diluent gas shall
complete a minimum of one cycle of operation (sampling, analyzing, and
data recording) for each successive 15-minute period. Hourly averages
shall be computed using at least one data point in each 15-minute
quadrant of an hour. Notwithstanding this requirement, an hourly
average may be computed from at least two data points separated by a
minimum of 15 minutes (where the unit operates for more than one
quadrant in an hour) if data are unavailable as a result of performance
of calibration, quality assurance, preventative maintenance activities,
or backups of data from data acquisition and handling system, and
recertification events. When valid pounds per million Btu emission data
are not obtained because of continuous monitoring system breakdowns,
repairs, calibration checks or zero and span adjustments, emission data
must be obtained by using other monitoring systems approved by the EPA
to provide emission data for a minimum of 18 hours in each 24-hour
period and at least 22 out of 30 successive boiler operating days.
(6) Recordkeeping and reporting requirements. Unless otherwise
stated all requests, reports, submittals, notifications and other
communications to the Regional Administrator required by this section
shall be submitted unless instructed otherwise to the Director, Air and
Radiation Division, U.S. Environmental Protection Agency, Region 7,
11201 Renner Boulevard, Lenexa, Kansas 66219. For each unit subject to
the emissions limitation in this section and upon completion of CEMS as
required in this section, the owner or operator shall comply with the
following requirements:
(i) The following information shall be reported to the Regional
Administrator, EPA Region 7, and the Nebraska Department of Energy and
the Environmental, for each boiler operating day. The report shall be
submitted no later than 30 days following the end of each semi-annual
calendar period (e.g., June 30, December 31).
(ii) For each SO2 emission limit in paragraph (c)(1) of
this section, comply with the notification, reporting, and
recordkeeping requirements for CEMS compliance monitoring in 40 CFR
60.7 (c) and (d).
(iii) For each day, provide the total SO2 emitted that
day by each emission unit covered under (c)(1). For any hours on any
unit where data for hourly pounds or heat input is missing, identify
the unit number and monitoring device that did not produce valid data
that caused the missing hour.
(iv) For the unit covered under (c)(2) and (d)(2), records
sufficient to demonstrate that the fuel for the unit is pipeline
natural gas.
(v) Records for demonstrating compliance with the SO2
and PM emission limitations in this section shall be maintained for at
least five years.
(A) Calendar date.
(B) The average SO2 emission rates, in lb/MMBtu, for
each 30 successive boiler operating day period, ending with the last
30-day period in the semi-annual reporting period; reasons for non-
compliance with the emission standards; and, description of corrective
actions taken.
(C) Identification of the boiler operating days for which pollutant
or diluent data have not been obtained by an approved method for at
least 75 percent of the hours of operation of the facility;
justification for not obtaining sufficient data; and description of
corrective actions taken.
(D) Identification of the ``F'' factor used for calculations,
method of determination, and type of fuel combusted.
(E) Identification of times when hourly averages have been obtained
based on manual sampling methods.
(F) Identification of the times when the pollutant concentration
exceeded full span of the CEMS.
(G) Description of any modifications to CEMS which could affect the
ability of the CEMS to comply with Performance Specifications 2 or 3 of
40 CFR 60.51, subpart Da.
(7) Equipment operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including the
associated air pollution control equipment in a manner consistent with
good air pollution control practices for minimizing emissions.
Determination of whether acceptable operating and maintenance
procedures are being used will be based on information available to the
Regional Administrator which may include, but is not limited to,
monitoring results, review of operating and maintenance procedures, and
inspection of the unit.
(8) Enforcement.
(i) Notwithstanding any other provision in this implementation
plan, any credible evidence or information relevant as to whether the
unit would have been in compliance with applicable requirements if the
appropriate performance or compliance test had been performed, can be
used to establish whether or not the owner or operator has violated or
is in violation of any standard or applicable implementation plan.
(ii) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to startup, shutdown or malfunction
shall constitute a violation of the applicable emission limit.
[FR Doc. 2024-16697 Filed 7-31-24; 8:45 am]
BILLING CODE 6560-50-P